In the oil and gas industry, seismic prospecting techniques are commonly used to aid in the search for and evaluation of subterranean hydrocarbon deposits. In seismic prospecting, a seismic source is used to generate a physical impulse (known as a "seismic signal") that propagates into the earth and is at least partially reflected by subsurface seismic reflectors (i.e., interfaces between underground formations having different acoustic impedances). The reflected signals (known as "reflections") are detected and recorded by seismic receivers located at or near the surface of the earth, in an overlying body of water, or at known depths in boreholes, and the resulting seismic data may be processed to yield information relating to the subsurface formations.
The seismic energy recorded by each seismic receiver is known as a "seismic data trace." Seismic data traces typically contain both the desired primary reflections and one or more unwanted noise components that can interfere with the processing and interpretation of the desired the primary reflections. These noises may include random noise, multiple reflections, converted waves, and surface waves. Conventional noise suppression methods typically exploit some difference between the noise to be suppressed and the primary reflections (e.g., different frequency band or different dip). Frequently, however, these differences are not sufficient to allow a clean separation between the desired primary reflections and the targeted noise.
In the case where the unwanted noise is due to multiple reflections (hereinafter referred to as "multiples"), some prior art noise suppression techniques take advantage of differences between the normal moveout (NMO) velocities (hereinafter referred to as "moveout velocities") of the primary reflections and the multiples in a common-midpoint (CMP) gather of seismic data traces (i.e., a set of seismic data traces having the same midpoint but different source-to-receiver offset distances). Methods such as the Radon transform and velocity-stack inversion can be particularly useful in distinguishing the primary reflections from the multiples. These methods decompose the seismic data traces in the CMP gather into a set of moveout parabolas or hyperbolas in which the multiples can be identified and suppressed on the basis of moveout velocity differences.
Conventional velocity-based multiple suppression techniques can often be used to suppress multiples such as the peg-leg multiple illustrated in FIG. 1. FIG. 1 shows a seismic source 10 and a seismic receiver 12 located at or near the surface 14 of a body of water 16. A subsurface reflector 18 is located a distance below the water bottom 20. FIG. 1 shows two raypaths from seismic source 10 to seismic receiver 12. (For simplicity, FIG. 1 assumes a constant seismic velocity from source 10 to receiver 12 for both raypaths.) For primary raypath 22 (solid line), the seismic signal propagates downwardly from seismic source 10 to reflection point 24 on subsurface reflector 18 and then upwardly to seismic receiver 10. In other words, for primary raypath 22, the seismic signal is reflected only once. However, for peg-leg multiple raypath 26 (dashed line), the seismic signal is reflected three times, once at reflection point 28 on subsurface reflector 18, once at point 30 on the surface 14 of body of water 16, and once at point 32 on the water bottom 20.
As would be well known to persons skilled in the art, multiples resulting from reverberation of the seismic energy within the water layer (hereinafter referred to as "water-bottom multiples") may involve several reflections in the water layer, and these reflections may occur at either or both ends of the raypath. Water-bottom multiples may have amplitudes comparable to the amplitude of the related primary reflection. Therefore, it is important to remove these multiples from the seismic data. In shallow water, water-bottom multiples can be easily removed by deconvolution techniques. In deep water, conventional velocity-based multiple suppression techniques can satisfactorily eliminate these multiples. However, velocity-based techniques are unable to satisfactorily suppress water-bottom multiples in intermediate water depths--ranging from about 100 meters to about 300 meters--because the difference between the moveout velocity of the primary reflection and the moveout velocity of the multiple is insufficient for satisfactory separation.
Prior art multiple suppression techniques do not make use of all available information. For example, an estimate of the water depth is usually available, either from direct measurements (e.g., by using sonar), or by examination of near-offset traces for multiple reflections. In the marine environment, the shape of the seismic energy generated by the source (i.e., the seismic wavelet) is usually known. Prior art multiple suppression techniques do not make use of this information in the multiple suppression process.
From the foregoing, it can be seen that there is a need for an improved method for suppressing multiple reflections, especially water-bottom multiples occurring in intermediate water depths, during processing of seismic data. Preferably, such a method should make use of any additional information which may be available, such as the water depth and the shape of the seismic wavelet. The present invention satisfies this need.